The present disclosure relates in general to bearing assemblies for downhole motors used in drilling of oil, gas, and water wells. The present disclosure also relates to drive systems incorporated in such downhole motors.
In drilling a wellbore into the earth, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of an assembly of drill pipe sections connected end-to-end (commonly referred to as a “drill string”), and then rotate the drill string so that the drill bit progresses downward into the earth to create the desired wellbore. In conventional vertical wellbore drilling operations, the drill string and bit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the wellbore (or, in offshore drilling operations, on a seabed-supported drilling platform or a suitably adapted floating vessel).
During the drilling process, a drilling fluid (also commonly referred to in the industry as “drilling mud”, or simply “mud”) is pumped under pressure downward from the surface through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the annular space between the drill string and the wellbore. The drilling fluid, which may be water-based or oil-based, is typically viscous to enhance its ability to carry wellbore cuttings to the surface. The drilling fluid can perform various other valuable functions, including enhancement of drill bit performance (e.g., by ejection of fluid under pressure through ports in the drill bit, creating mud jets that blast into and weaken the underlying formation in advance of the drill bit), drill bit cooling, and formation of a protective cake on the wellbore wall (to stabilize and seal the wellbore wall).
Particularly since the mid-1980s, it has become increasingly common and desirable in the oil and gas industry to use “directional drilling” techniques to drill horizontal and other non-vertical wellbores, to facilitate more efficient access to and production from larger regions of subsurface hydrocarbon-bearing formations than would be possible using only vertical wellbores. In directional drilling, specialized drill string components and “bottomhole assemblies” (BHAs) are used to induce, monitor, and control deviations in the path of the drill bit, so as to produce a wellbore of desired non-vertical configuration.
Directional drilling is typically carried out using a downhole motor (commonly referred to as a “mud motor”) incorporated into the drill string immediately above the drill bit. A typical prior art mud motor includes several primary components, as follows (in order, starting from the top of the motor assembly):                a top sub adapted to facilitate connection to the lower end of a drill string (“sub” being the common general term in the oil and gas industry for any small or secondary drill string component);        a power section comprising a positive displacement motor of well-known type, with a helically-vaned rotor eccentrically rotatable within a stator section;        a drive shaft housing configured to be straight, bent, or incrementally adjustable between zero degrees and a maximum angle;        a drive shaft enclosed within the drive shaft housing, with the upper end of the drive shaft being operably connected to the rotor of the power section; and        a bearing section comprising a cylindrical mandrel coaxially and rotatably disposed within a cylindrical housing, with an upper end coupled to the lower end of the drive shaft, and a lower end adapted for connection to a drill bit.        
The mandrel is rotated by the drive shaft, which rotates in response to the flow of drilling fluid under pressure through the power section. The mandrel rotates relative to the cylindrical housing, which is connected to the drill string.
Conventional mud motors include power sections that use either a Moineau drive system or a turbine-type drive system. These types of power sections are relatively long, with typical lengths of 15-20 feet for Moineau-type power sections and 20-30 feet for turbines for motor sizes between 5″ and 8″ in diameter. For directional drilling with a bent motor assembly, it is optimal to position the bend within a few feet of the bit in order to achieve suitable levels of hole curvature and reasonable steerability of the assembly. Having the bend located above the power section or turbine would be too great a distance from the bit to be effective, so this requires the bend to be located below the power section or turbine. The bend is typically incorporated within the drive shaft housing. The driveshaft typically comprises universal joints to accommodate the angular misalignment between the power section and bearing assembly, as well as the eccentric operation in the case of a Moineau power section. The driveshaft U-joints and threaded connections are typically the weakest parts of the motor assembly and the most common locations for fractures to occur.
U.S. Pat. No. 6,280,169, No. 6,468,061, No. 6,939,117, and No. 6,976,832 (all of which are hereby incorporated by reference in their entirety) disclose similar types of fluid-powered rotary drive mechanisms. These mechanisms are capable of outputting levels of rotary speed and torque comparable to Moineau and turbine-type power sections, but in power sections as short as one to three feet in length. These mechanisms comprise a system of longitudinal lobes and gates, with intake and exhaust ports for directing fluid to build pressure between the lobes and gates to drive the rotation of the motor. The mechanisms operate with concentric rotation between the inner shaft and outer housing. The shorter length and concentric operation allow any of these drive systems to be incorporated directly within or attached to the mud motor bearing assembly, with no need for a driveshaft assembly with universal joints. The fixed or adjustable bent housing can be attached above the drive section while maintaining a bit-to-bend length that is as short as or shorter than in conventional downhole motors. The resulting overall length of the motor is dramatically shorter than in conventional assemblies.
These drive mechanisms do not require any elastomeric elements, in contrast to Moineau-type drive systems which incorporate elastomeric stator elements that limit the operational temperature for a Moineau-type system to a maximum of about 325-350° F. Additionally, the performance of Moineau-type drive systems tapers off sharply above 140° F. Therefore, these concentrically-operating drive systems are suitable for use in extremely high temperature and geothermal applications (500+ degrees F.) that are beyond the limits of Moineau-type systems, with little or no drop in performance.